Of interest to one aspect of the present invention relating to selective opening of ports of a plurality of valve subs within a fracking string to allow fracking of a formation at discrete/selected intervals along a wellbore, prior art designs such as those disclosed in U.S. Pat. No. 6,907,936 (esp. FIG. 1b & FIGS. 3A, 3B), U.S. Pat. No. 6,095,541, US 2006/0124310, and SPE 51177 (September 1998) generally teach a number of valve subs each having a sliding cylindrical sleeve and an associated circular ball seat therein. The slidable sleeve covers a frac port to keep it closed when the sleeve is in a first (closed position), and the sleeve may be moved to a second (open) position which uncovers the frac port to allow frac fluid to be supplied through a pre-perforated casing to thereby fracture the formation.
In one aspect of such prior art a ball seat is provided for each slidable sleeve. The ball seat for each slidable sleeve reduces in diameter for each sleeve of an associated valve sub the further downhole a particular valve sub and associated sliding sleeve is placed downhole.
In operation, to progressively open frac ports within each of the valve subs, commencing with the most downhole valve sub-member, a first ball of small diameter is injected downhole and flows past larger diameter ball seats in associated valve subs [thereby leaving the slidable sleeve therein in a position covering the frac ports] until the most downhole sleeve is reached having the smallest diameter ball seat, which ball seat is smaller in diameter than the first ball. The first ball's further downhole motion is thus arrested by the smaller-diameter ball seat, and fluid pressure uphole of the ball forces the first ball, the ball seat, and associated slidable sleeve to move downhole, thereby uncovering and thus opening the frac port within the most downhole valve sub. Fluid under pressure is continued to be injected and pumped down the wellbore to frac the formation in the location of the open port in such wellbore. Thereafter, a second ball, of slightly larger diameter, is injected downhole, which second ball is larger in diameter than the ball seat as contained in the second-lowermost (downhole) valve sub. Now the second ball's further downhole motion is thus arrested by the smaller-diameter ball seat, and fluid pressure uphole of the second ball forces the first ball, the ball seat, and associated slidable sleeve to move downhole, thereby uncovering and thus opening the frac port within the second most downhole valve sub.
The above process is repeated, using progressively larger diameter balls, until all of the slidable sleeves in each of the valve subs has been opened, and the formation fractured in the region of the open frac ports of each of the valve subs.
Thereafter, a milling sub is passed through the bore of each of the valve subs to mill out and thereby remove each of the balls and ball seats, to thereby allow hydrocarbons flowing into the valve sub to be freely pumped up to surface.
Such prior art method and apparati possess at least four distinct disadvantages.
Firstly, one shortcoming of the ball valve seat mechanisms as described above is that such mechanism cannot be cemented into place within a casing due to the fact there is no way to then clean or wipe the cement out of the ball seat mechanism for subsequent use. Such prior art systems thus typically need to be used with a liner with open hole packers, which adds to the cost.
A second disadvantage is that due to the progressively decreasing diameter of the ball seat in each of the valve subs, the volume and rate of fracking fluid flow is thus seriously and undesirably restricted in the most downhole regions of the wellbore, and typically a flow rate of 15 cubic meters per minute [with wellbores of the typical 6-9 inch (15-23 cm) diameter] cannot be obtained.
A third disadvantage of the “graduated size ball drop” mechanisms of the prior art is that due to the need to have a plurality of balls of different (but distinct) diameters, the number of valve subs can typically be no greater than 23 stages, and thus typically no more than 23 areas along a wellbore can be fracked at a single time, unless one or more ball seats incorporate a release mechanism such as that disclosed in U.S. Pat. No. 4,893,678 (i.e. a “kickover” mechanism) to allow the ball to pass through the associated ball seat after having actuated the sliding sleeve to open the associated port, to allow additional one or more downhole subs to have their respective frac ports opened by the same valve.
A forth disadvantage is that a milling operation may need to be conducted, after fracking, to remove the balls to allow the well to be pumped.
In order to overcome the above disadvantages with the prior art graduated-size ball drop mechanisms and methods, US 2013/0168098 (CA 2,797,821) (having a common inventor to the present invention) teaches in one embodiment a dart 22, as shown in FIGS. 7-9 thereof, having “keys” 42, which keys 42 only engage the keyways 32 of a corresponding valve sub 10 (ref. FIG. 5 and para. [009], [0039], with the keys 42 becoming progressively wider with each successive valve sub 10 disposed in well casing 49 towards the top of well 46. Finer graduations in dart key width and corresponding sleeve groove width can be implanted, and in doing so, it was postulated in such application that the number of valve subs in a single casing string could be increased to something in the range of 16 to 30 or more.
Notably, however, the keyways in such configuration run longitudinally of the valve sub, and are not circumferential, as is clear from FIG. 6 thereof.
In an alternative configuration shown in FIGS. 12A-15 of US 2013/0168098, a dart 22 (ref. FIG. 14 thereof) is provided, having a key profile 54 which is biased towards the inner wall of sliding piston (sleeve) 20 (ref. para. [0044]. When the key profile 58 on a particular dart 22 matches a key profile on piston 20 within a particular valve sub 10, the keyways engage and the piston 20 is caused to move. Specifically, as noted at para. [0048], in such embodiment dart 22 can travel through casing 49 until it reaches a matching key profile 54, where it then latches into piston 20 and locking shoulder 56. The top of dart cup 44 on dart 22 can form a seal within valve body 12, and shear pins 25 are then caused to shear under fluid pressure exerted on dart 22 which causes engaged piston 20 to move down the well, to thereby open ports 14, which can then supply fluid pressure to the formation at such location. FIGS. 15a, 15B, 15C, 15D show a series of possible key profiles 54 and dart profiles 58 for such embodiment. Notably, however, all of such profiles teach a plurality of grooves in the interior surface of piston (sleeve) 20, with the “keying” dependent on the relative number and spacing of the grooves relative to each other to provide the selective “keying” arrangement.
Disadvantageously, while such above design of US 2013/0168098/CA 2,797,821 eliminates the problem of reduced bore diameter and consequent restriction of flow of fluid, such as fracking fluid and moreover further increases the number of possible valve subs which can be used due to the infinite number of “key” combinations using different numbers and relative spacing between the circumferential grooves formed on the inner wall of piston 20 which form the key profile 54 [ref. para. 0044], machining of piston/sleeve 20 and darts 22 in the manner disclosed in US 2013/0168098 becomes unduly time-consuming and expensive.
CA 2,860,134 (WO 2013/048810) entitled “Multizone Treatment System” at inter alia FIG. 2 thereof teaches a system and method for successively selectively opening a number of sliding sleeves along a wellbore to allow fluid injection at the location of each of the sliding sleeves. The sliding sleeves each have a circumferential radial groove, the width of which differs, becoming progressively larger for each valve sub-members the more downhole the valve sub and associated sliding sleeve may be positioned. Again, however, and disadvantageously, after fracking of the well, a reamer must be inserted downhole to remove all dart members which have become coupled to associated sleeves, to thereby “open up” the wellbore for maximum production. No bypass is disclosed, for use in removing the dart members.
This background information is provided for the purpose of making known information believed by the applicant to be of possible relevance to the present invention. No admission is necessarily intended, nor should be construed, that any of the preceding information, or the reference in the drawings to “prior art” constitutes prior art against the present invention.